TransAtlantic Petroleum (TAT) 10-Q 2014 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended: March 31, 2014

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                    to                    

Commission file number: 001-34574

TRANSATLANTIC PETROLEUM LTD.

(Exact name of registrant as specified in its charter)

Bermuda	None
(State or Other Jurisdiction of Incorporation or Organization)	(I.R.S. Employer Identification No.)
16803 Dallas Parkway Addison, Texas	75001
(Address of Principal Executive Offices)	(Zip Code)

Registrant’s Telephone Number, Including Area Code: (214) 220-4323

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant is required to submit and post such files).    Yes  x    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer	¨	Accelerated filer	x
Non-accelerated filer	¨  (Do not check if a smaller reporting company)	Smaller reporting company	¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x

As of May 1, 2014, the registrant had 37,402,698 common shares outstanding.

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION
Item 1.Financial Statements
Consolidated Balance Sheets as of March 31, 2014 and December 31, 2013	1
Consolidated Statements of Comprehensive Income for the Three Months Ended March 31, 2014 and 2013	2
Consolidated Statements of Equity for the Three Months Ended March 31, 2014	3
Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2014 and 2013	4
Notes to Consolidated Financial Statements	5
Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations	16
Item 3.Quantitative and Qualitative Disclosures About Market Risk	25
Item 4.Controls and Procedures	25
PART II. OTHER INFORMATION
Item 1.Legal Proceedings	26
Item 1A.Risk Factors	26
Item 2.Unregistered Sales of Equity Securities and Use of Proceeds	26
Item 3.Defaults Upon Senior Securities	26
Item 4.Mine Safety Disclosures	26
Item 5.Other Information	26
Item 6.Exhibits	27

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

TRANSATLANTIC PETROLEUM LTD.

Consolidated Balance Sheets

(in thousands of U.S. Dollars, except share data)

	March 31, 2014			December 31, 2013
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	16,708		$	12,881
Accounts receivable
Oil and natural gas sales, net		30,940			30,619
Joint interest and other		9,218			15,348
Related party		472			1,004
Prepaid and other current assets		5,681			5,072
Deferred income taxes		2,322			2,239
Assets held for sale		29			536
Total current assets		65,370			67,699
Property and equipment:
Oil and natural gas properties (successful efforts method)
Proved		273,968			260,857
Unproved		52,559			54,392
Equipment and other property		37,784			39,916
		364,311			355,165
Less accumulated depreciation, depletion and amortization		(111,787	)		(104,193	)
Property and equipment, net		252,524			250,972
Other long-term assets:
Other assets		8,215			8,880
Note receivable – related party		11,500			11,500
Goodwill		7,344			7,535
Total other assets		27,059			27,915
Total assets	$	344,953		$	346,586
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	12,582		$	16,712
Accounts payable — related party		18,871			23,090
Accrued liabilities		20,047			20,658
Derivative liabilities		3,384			3,737
Asset retirement obligations		394			610
Loans payable		26,700			43,284
Liabilities held for sale		7,455			7,559
Total current liabilities		89,433			115,650
Long-term liabilities:
Asset retirement obligations		10,291			10,286
Accrued liabilities		6,439			6,487
Deferred income taxes		17,824			16,134
Loan payable		49,766			26,482
Derivative liabilities		2,869			4,230
Total long-term liabilities		87,189			63,619
Total liabilities		176,622			179,269
Commitments and contingencies
Shareholders’ equity:
Common shares, $0.10 par value, 100,000,000 shares authorized; 37,402,698 shares issued and outstanding as of March 31, 2014 and 37,340,206 shares issued and outstanding as of December 31, 2013		3,740			3,734
Additional paid-in capital		542,421			542,091
Accumulated other comprehensive loss		(68,280	)		(64,985	)
Accumulated deficit		(309,550	)		(313,523	)
Total shareholders’ equity		168,331			167,317
Total liabilities and shareholders’ equity	$	344,953		$	346,586

The accompanying notes are an integral part of these consolidated financial statements.

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TRANSATLANTIC PETROLEUM LTD.

Consolidated Statements of Comprehensive Income

(Unaudited)

(U.S. Dollars and shares in thousands, except per share amounts)

	For the Three Months Ended March 31,
	2014			2013
Revenues:
Oil and natural gas sales	$	32,984		$	32,725
Sales of purchased natural gas		545			806
Other		117			513
Total revenues		33,646			34,044
Costs and expenses:
Production		4,131			5,527
Exploration, abandonment and impairment		4,141			3,864
Cost of purchased natural gas		485			712
Seismic and other exploration		3,294			243
Revaluation of contingent consideration		(2,500	)		—
General and administrative		6,552			7,523
Depreciation, depletion and amortization		10,090			8,976
Accretion of asset retirement obligations		98			129
Total costs and expenses		26,291			26,974
Operating income		7,355			7,070
Other income (expense):
Interest and other expense		(1,203	)		(890	)
Interest and other income		273			375
Gain (loss) on commodity derivative contracts		962			(776	)
Foreign exchange loss		(1,344	)		(487	)
Total other expense		(1,312	)		(1,778	)
Income from continuing operations before income taxes		6,043			5,292
Current income tax expense		(69	)		(1,339	)
Deferred income tax expense		(1,981	)		(921	)
Net income from continuing operations		3,993			3,032
Net loss from discontinued operations, net of taxes		(20	)		(93	)
Net income	$	3,973		$	2,939
Other comprehensive loss:
Foreign currency translation adjustment		(3,295	)		(2,836	)
Comprehensive income	$	678		$	103
Net income per common share:
Basic net income per common share:
Continuing operations	$	0.11		$	0.08
Discontinued operations	$	0.00		$	0.00
Weighted average common shares outstanding		37,392			36,888
Diluted net income per common share:
Continuing operations	$	0.11		$	0.08
Discontinued operations	$	0.00		$	0.00
Weighted average common and common equivalent shares outstanding		37,392			36,888

The accompanying notes are an integral part of these consolidated financial statements.

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TRANSATLANTIC PETROLEUM LTD.

Consolidated Statements of Equity

(Unaudited)

(U.S. Dollars and shares in thousands)

	Common Shares		Common Shares ($)		Additional Paid-in Capital			Accumulated Other Comprehensive Loss			Accumulated Deficit			Total Shareholders’ Equity
Balance at December 31, 2013		37,340	$	3,734	$	542,091		$	(64,985	)	$	(313,523	)	$	167,317
Issuance of restricted stock units		63		6		(6	)		—			—			—
Share-based compensation		—		—		396			—			—			396
Tax withholding on restricted stock units		—		—		(60	)		—			—			(60	)
Foreign currency translation adjustments		—		—		—			(3,295	)		—			(3,295	)
Net income		—		—		—			—			3,973			3,973
Balance at March 31, 2014		37,403	$	3,740	$	542,421		$	(68,280	)	$	(309,550	)	$	168,331

The accompanying notes are an integral part of these consolidated financial statements.

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TRANSATLANTIC PETROLEUM LTD.

Consolidated Statements of Cash Flows

(Unaudited)

(in thousands of U.S. Dollars)

	For the Three Months Ended March 31,
	2014			2013
Operating activities:
Net income	$	3,973		$	2,939
Adjustment for net loss from discontinued operations		20			93
Net income from continuing operations		3,993			3,032
Adjustments to reconcile net income to net cash provided by operating activities:
Share-based compensation		396			382
Foreign currency loss		2,413			490
(Gain) loss on commodity derivative contracts		(962	)		776
Cash settlement on commodity derivative contracts		(752	)		(1,252	)
Amortization of loan financing costs		127			128
Deferred income tax expense		1,981			921
Exploration, abandonment and impairment		4,141			3,864
Depreciation, depletion and amortization		10,090			8,976
Accretion of asset retirement obligations		98			129
Revaluation of contingent consideration		(2,500	)		—
Changes in operating assets and liabilities
Accounts receivable		5,207			9,166
Prepaid expenses and other assets		(401	)		219
Accounts payable and accrued liabilities		4,320			(7,182	)
Net cash provided by operating activities from continuing operations		28,151			19,649
Net cash used in operating activities from discontinued operations		(20	)		(1,072	)
Net cash provided by operating activities		28,131			18,577
Investing activities:
Additions to oil and natural gas properties		(30,925	)		(13,423	)
Additions to equipment and other properties		(267	)		(1,133	)
Restricted cash		—			(7,110	)
Net cash used in investing activities from continuing operations		(31,192	)		(21,666	)
Net cash provided by investing activities from discontinued operations		500			1,016
Net cash used in investing activities		(30,692	)		(20,650	)
Financing activities:
Tax withholding on restricted stock units		(60	)		—
Loan proceeds		12,013			13,589
Loan repayment		(5,313	)		(6,589	)
Net cash provided by financing activities from continuing operations		6,640			7,000
Effect of exchange rate changes on cash		(252	)		(267	)
Net increase in cash and cash equivalents		3,827			4,660
Cash and cash equivalents, beginning of period		12,881			14,768
Cash and cash equivalents, end of period	$	16,708		$	19,428
Supplemental disclosures:
Cash paid for interest	$	766		$	702
Cash paid for taxes	$	—		$	396

The accompanying notes are an integral part of these consolidated financial statements.

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TRANSATLANTIC PETROLEUM LTD.

Notes to Consolidated Financial Statements

(unaudited)

1. General

Nature of operations

TransAtlantic Petroleum Ltd. (together with its subsidiaries, “we,” “us,” “our,” the “Company” or “TransAtlantic”) is an international oil and natural gas company engaged in acquisition, exploration, development and production. We have focused our operations in countries that have established yet underexplored petroleum systems, are net importers of petroleum, have an existing petroleum transportation infrastructure and provide favorable commodity pricing, royalty rates and tax rates to exploration and production companies. As of March 31, 2014, we held interests in developed and undeveloped oil and natural gas properties in Turkey and Bulgaria. As of May 1, 2014, approximately 40% of our outstanding common shares were beneficially owned by N. Malone Mitchell 3rd, our chief executive officer and chairman of our board of directors.

Basis of presentation

Our consolidated financial statements are expressed in U.S. Dollars and have been prepared by management in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”). All amounts in these notes to the consolidated financial statements are in U.S. Dollars unless otherwise indicated. In preparing financial statements, management makes informed judgments and estimates that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, management reviews estimates, including those related to fair value measurements associated with acquisitions and financial derivatives, the recoverability and impairment of long-lived assets and goodwill, contingencies and income taxes. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates.

Certain information and footnote disclosures normally included in the consolidated financial statements prepared in accordance with U.S. GAAP have been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our Form 10-K for the year ended December 31, 2013.

2. Recent accounting pronouncements

In April 2014, the Financial Accounting Standard Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-08,Reporting Discontinued Operations and Disclosures of Components of an Entity(“ASU 2014-08”). ASU 2014-08 revises the definition of discontinued operations by limiting discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have (or will have) a major effect on an entity’s operations and financial results, removing the lack of continuing involvement criteria and requiring discontinued operations reporting for the disposal of an equity method investment that meets the definition of discontinued operations. The update also requires expanded disclosures for discontinued operations, including disclosure of pretax profit or loss of an individually significant component of an entity that does not qualify for discontinued operations reporting. The update is effective prospectively to all periods beginning after December 15, 2014. We do not expect the adoption of ASU 2014-08 to have a material impact on our consolidated financial statements or results of operations.

We have reviewed other recently issued, but not yet adopted, accounting standards in order to determine their effects, if any, on our consolidated results of operations, financial position and cash flows. Based on that review, we believe that none of these pronouncements will have a significant effect on current or future earnings or operations.

3. Property and equipment

Oil and natural gas properties

The following table sets forth the capitalized costs under the successful efforts method for our oil and natural gas properties as of:

	March 31, 2014			December 31, 2013
	(in thousands)
Oil and natural gas properties, proved:
Turkey	$	273,344		$	260,232
Bulgaria		624			625
Total oil and natural gas properties, proved		273,968			260,857
Oil and natural gas properties, unproved:
Turkey		48,413			51,273
Bulgaria		4,146			3,119
Total oil and natural gas properties, unproved		52,559			54,392
Gross oil and natural gas properties		326,527			315,249
Accumulated depletion		(104,180	)		(96,958	)
Net oil and natural gas properties	$	222,347		$	218,291

At March 31, 2014 and December 31, 2013, we excluded $4.1 million and $1.5 million, respectively, from the depletion calculation for proved development wells currently in progress and for costs associated with fields currently not in production.

At March 31, 2014, the capitalized costs of our oil and natural gas properties, net of accumulated depletion, included $33.2 million relating to acquisition costs of proved properties, which are being depleted by the unit-of-production method using total proved reserves, and $132.5 million relating to well costs and additional development costs, which are being depleted by the unit-of-production method using proved developed reserves.

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At December 31, 2013, the capitalized costs of our oil and natural gas properties, net of accumulated depletion, included $35.5 million relating to acquisition costs of proved properties, which are being depleted by the unit-of-production method using total proved reserves, and $126.9 million relating to well costs and additional development costs, which are being depleted by the unit-of-production method using proved developed reserves.

Impairment and dry hole costs

During the three months ended March 31, 2014 and 2013, we recorded $4.1 million and $3.9 million of impairment and exploratory dry hole costs, respectively. Of the $4.1 million of costs incurred during the three months ended March 31, 2014, approximately $1.1 million was related to cash spent during the three months ended March 31, 2014.

Capitalized cost greater than one year

As of March 31, 2014, we had $2.6 million and $1.7 million of exploratory well costs capitalized for the Kazanci-5 and Hayrabolu-10 wells, which we spud in September 2012 and February 2013, respectively. We are currently recompleting the Kazanci-5 well in the Osmancik and Danismen formation intervals and plan to put it on production in the next few months. The Hayrabolu-10 well has similar characteristics to the Kazanci-5 well, and we are waiting on the results of the Kazanci-5 well to develop the completion plan for it.

Equipment and other property

The historical cost of equipment and other property, presented on a gross basis with accumulated depreciation, is summarized as follows:

	March 31, 2014			December 31, 2013
	(in thousands)
Other equipment	$	3,560		$	2,678
Inventory		22,179			24,318
Gas gathering system and facilities		4,371			4,485
Vehicles		316			321
Leasehold improvements, office equipment and software		7,358			8,114
Gross equipment and other property		37,784			39,916
Accumulated depreciation		(7,607	)		(7,235	)
Net equipment and other property	$	30,177		$	32,681

We classify our materials and supply inventory, including steel tubing and casing, as long-term assets because such materials will ultimately be classified as long-term assets when the material is used in the drilling of a well.

At March 31, 2014, we excluded $22.2 million of inventory and $0.9 million of software from depreciation, as the inventory and software had not been placed into service. At December 31, 2013, we excluded $24.3 million of inventory and $0.7 million of software from depreciation, as the inventory and software had not been placed into service.

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4. Asset retirement obligations

The following table summarizes the changes in our asset retirement obligations for the three months ended March 31, 2014 and for the year ended December 31, 2013:

	March 31, 2014			December 31, 2013
	(in thousands)
Asset retirement obligations at beginning of period	$	10,896		$	11,958
Change in estimates		—			(7	)
Liabilities settled		(206	)		(296	)
Foreign exchange change effect		(271	)		(2,258	)
Additions		168			991
Accretion expense		98			508
Asset retirement obligations at end of period		10,685			10,896
Less: current portion		394			610
Long-term portion	$	10,291		$	10,286

Our asset retirement obligations are measured using primarily Level 3 inputs. The significant unobservable inputs to this fair value measurement include estimates of plugging costs, remediation costs, inflation rate and well life. The inputs are calculated based on historical data as well as current estimated costs.

5. Commodity derivative instruments

We use collar derivative contracts to economically hedge against the variability in cash flows associated with the forecasted sale of a portion of our future oil production. We have not designated the derivative contracts as hedges for accounting purposes, and accordingly, we record the derivative contracts at fair value and recognize changes in fair value in earnings as they occur.

To the extent that a legal right of offset exists, we net the value of our derivative contracts with the same counterparty in our consolidated balance sheets. All of our oil derivative contracts are settled based upon Brent crude oil pricing. We recognize gains and losses related to these contracts on a fair value basis in our consolidated statements of comprehensive income under the caption “Gain (loss) on commodity derivative contracts.” Settlements of derivative contracts are included in operating activities on our consolidated statements of cash flows under the caption “Cash settlement on commodity derivative contracts.” We are required under our amended and restated credit facility (the “Amended and Restated Credit Facility”) with BNP Paribas (Suisse) SA (“BNP Paribas”) and Standard Bank Plc (“Standard Bank”), to hedge between 30% and 75% of our anticipated production volumes in the Selmo and Arpatepe oil fields in Turkey.

During the three months ended March 31, 2014 and 2013, we recorded net gain on commodity derivative contracts of $1.0 million and a net loss of $0.8 million, respectively.

At March 31, 2013 and December 31, 2013, we had outstanding contracts with respect to our future crude oil production as set forth in the tables below:

Fair Value of Derivative Instruments as of March 31, 2014

Type	Period	Quantity (Bbl/day)		Weighted Average Minimum Price (per Bbl)		Weighted Average Maximum Price (per Bbl)		Estimated Fair Value of Liability
								(in thousands)
Collar	April 1, 2014—December 31, 2014		614	$	80.72	$	117.84	$	(192	)
								$	(192	)

		Collars						Additional Call
Type	Period	Quantity (Bbl/day)		Weighted Average Minimum Price (per Bbl)		Weighted Average Maximum Price (per Bbl)		Weighted Average Maximum Price (per Bbl)		Estimated Fair Value of Liability
										(in thousands)
Three-way collar contract	April 1, 2014—December 31, 2014		708	$	85.00	$	97.13	$	162.13	$	(1,988	)
Three-way collar contract	January 1, 2015—December 31, 2015		1,016	$	85.00	$	91.88	$	151.88		(4,073	)
										$	(6,061	)

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Fair Value of Derivative Instruments as of December 31, 2013

Type	Period		Quantity (Bbl/day)		Weighted Average Minimum Price (per Bbl)		Weighted Average Maximum Price (per Bbl)		Estimated Fair Value of Liability
									(in thousands)
Collar		January 1, 2014—December 31, 2014		622	$	80.83	$	118.07	$	(387	)
									$	(387	)

			Collars						Additional Call
Type	Period		Quantity (Bbl/day)		Weighted Average Minimum Price (per Bbl)		Weighted Average Maximum Price (per Bbl)		Weighted Average Maximum Price (per Bbl)		Estimated Fair Value of Liability
											(in thousands)
Three-way collar contract		January 1, 2014—December 31, 2014		726	$	85.00	$	97.13	$	162.13	$	(3,350	)
Three-way collar contract		January 1, 2015—December 31, 2015		1,016	$	85.00	$	91.88	$	151.88		(4,230	)
											$	(7,580	)

Balance sheet presentation

The following table summarizes both: (i) the gross fair value of our commodity derivative instruments by the appropriate balance sheet classification even when the commodity derivative instruments are subject to netting arrangements and qualify for net presentation in our consolidated balance sheets and (ii) the net recorded fair value as reflected on our consolidated balance sheets at March 31, 2014 and December 31, 2013.

		As of March 31, 2014
Underlying commodity	Location on Balance Sheet	Gross Amount of Recognized Liabilities		Gross Amount Offset in the Consolidated Balance Sheet		Net Amount of Liabilities Presented in the Consolidated Balance Sheet
		(in thousands)
Crude oil	Current liabilities	$	3,384	$	—	$	3,384
Crude oil	Long-term liabilities	$	2,869	$	—	$	2,869
		As of December 31, 2013
Underlying commodity	Location on Balance Sheet	Gross Amount of Recognized Liabilities		Gross Amount Offset in the Consolidated Balance Sheet		Net Amount of Liabilities Presented in the Consolidated Balance Sheet
		(in thousands)
Crude oil	Current liabilities	$	3,737	$	—	$	3,737
Crude oil	Long-term liabilities	$	4,230	$	—	$	4,230

6. Loans payable

As of the dates indicated, our third-party debt consisted of the following:

	March 31, 2014		December 31, 2013
Floating Rate Debt	(in thousands)
Amended and Restated Credit Facility	$	49,766	$	49,766
TBNG credit facility		26,700		20,000
Loans payable		76,466		69,766
Less: current portion		26,700		43,284
Long-term portion	$	49,766	$	26,482

Amended and Restated Credit Facility

On May 18, 2011, DMLP, Ltd. (“DMLP”), TransAtlantic Exploration Mediterranean International Pty Ltd (“TEMI”), Talon Exploration, Ltd. (“Talon Exploration”), TransAtlantic Turkey, Ltd. (“TransAtlantic Turkey”) and Petrogas (collectively, and together with Amity, the “Borrowers”) entered into the Amended and Restated Credit Facility. Each of the Borrowers is our wholly owned subsidiary. In July 2011, Amity executed a joinder agreement and became a borrower under the Amended and Restated Credit Facility. The Amended and Restated Credit Facility is guaranteed by us and each of TransAtlantic Petroleum (USA) Corp. and TransAtlantic Worldwide.

Availability under the Amended and Restated Credit Facility is subject to a borrowing base. The borrowing base is re-determined quarterly on January 1st, April 1st, July 1st and October 1st of each year. Following our borrowing base redetermination on January 1, 2014, the borrowing base is currently $43.1 million. At March 31, 2014, we had borrowed $49.8 million under the Amended and Restated Credit Facility. The lenders have granted the Borrowers a waiver to extend until May 15, 2014 a mandatory prepayment due as a result of our borrowings exceeding the borrowing base.

At March 31, 2013, we were not in compliance with Section 8.17(a) of our Amended and Restated Credit Facility, which requires the Borrowers to maintain a current ratio of not less than 1.10:1.0. The lenders have granted the Borrowers a waiver on the current ratio requirement through March 31, 2015.

Senior Credit Facility

On May 6, 2014, the Borrowers entered into a senior secured credit facility (the “Senior Credit Facility”) with BNP Paribas and the International Finance Corporation (“IFC”). The Senior Credit Facility is guaranteed by TransAtlantic Petroleum Ltd. and each of TransAtlantic Petroleum (USA) Corp. and TransAtlantic Worldwide. We intend to use borrowings under the Senior Credit Facility to pay off in full the Amended and Restated Credit Facility and to fund our oil and natural gas development and exploration activities in Turkey. See Note 13 Subsequent events.

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TBNG credit facility

On June 18, 2013, our wholly owned subsidiary Thrace Basin Natural Gas (Turkiye) Corporation (“TBNG”) entered into a 78.8 million New Turkish Lira (“TRY”) (approximately $36.0 million at March 31, 2014) unsecured line of credit with a Turkish bank, of which 60 million TRY is available in cash for TBNG and 18.8 million TRY is available in the form of non-cash bank guarantees and letters of credit for TBNG and several other of our wholly owned subsidiaries operating in Turkey. The interest rate is established at the time of each borrowing. We have made three borrowings under this credit facility, on October 9, 2013, November 5, 2013 and January 22, 2014 each of which has a one-year term at a fixed interest rate of 4.6% per annum. At maturity, we expect to renew the borrowings for one additional year at then current market interest rates. As of March 31, 2014, we had borrowed $26.7 million under this credit facility.

7. Contingencies relating to exploration permits

Selmo

We are involved in litigation with persons who claim ownership of a portion of the surface at the Selmo oil field in Turkey. These cases are being vigorously defended by TEMI and Turkish governmental authorities. We do not have enough information to estimate the potential additional operating costs we would incur in the event the purported surface owners’ claims are ultimately successful. Any adjustment arising out of the claims will be recorded when it becomes probable and measurable.

Morocco

In the second quarter of 2012, we were notified that the Moroccan government may seek to recover approximately $5.5 million in contractual obligations under our Tselfat exploration permit work program. In February 2013, the Moroccan government drew down our $1.0 million bank guarantee that was put in place to ensure our performance of the Tselfat exploration permit work program. Although we believe that the bank guarantee satisfies our contractual obligations, we recorded $5.0 million in accrued liabilities relating to our Tselfat exploration permit during 2012 for this contingency.

Aglen

In the second quarter of 2012, we were notified that the Bulgarian government may seek to recover approximately $2.0 million in contractual obligations under our Aglen exploration permit work program. Due to the Bulgarian government’s January 2012 ban on fracture stimulation and related activities, a force majeure event under the terms of the exploration permit was recognized by the government. Although we invoked force majeure, we recorded $2.0 million in general and administrative expense relating to our Aglen exploration permit during 2012 for this contractual obligation.

Direct Petroleum

In July 2013, we entered into a second amendment (the “Amendment”) to the Purchase Agreement with Direct Petroleum Exploration, LLC (“Direct”). The Amendment set forth a new obligation to drill and test the Deventci-R2 well by May 1, 2014. We completed the drilling and testing requirements pursuant to the Amendment during April 2014, which resulted in the reversal of the $2.5 million contingent liability recorded in 2011. The reversal is recognized in our consolidated statements of comprehensive income under the caption “Revaluation of contingent consideration” during the three months ended March 31, 2014.

In addition, the Amendment provides that we will issue $7.5 million in common shares if the Deventci-R2 well is a commercial success (as defined in the Purchase Agreement) on or prior to May 1, 2016. We will record any provision for this contingent consideration when it is estimable and probable. As of March 31, 2014, we had not recorded a contingent liability for this contingent consideration.

Additionally, the Amendment provides that if the Bulgarian government issues a production concession over the Stefenetz Concession Area, Direct will be entitled to a payment of $10.0 million in common shares, or a pro rata amount if the production concession is less than 200,000 acres. We do not have enough information to estimate the potential contingent liability we would incur in the event the Bulgarian government issues a production concession over the Stefenetz Concession Area. Any adjustment will be recorded when it becomes probable and estimable.

8. Shareholders’ equity

Reverse stock split

On March 4, 2014, our shareholders approved a 1-for-10 reverse stock split, which became effective March 6, 2014. Pursuant to the reverse stock split, all shareholders of record received one common share for each ten common shares owned (subject to minor adjustments as a result of fractional shares). The reverse stock split reduced the issued and outstanding common shares from 374,026,984 to 37,402,698. U.S. GAAP requires that the reverse stock split be applied retrospectively to all periods presented. As a result, all common share amounts and transactions herein have been adjusted to reflect the 1-for-10 reverse stock split.

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Restricted stock units

We recorded share-based compensation expense of $0.4 million for awards of restricted stock units (“RSUs”) for each of the three months ended March 31, 2014 and 2013.

As of March 31, 2014, we had approximately $2.2 million of unrecognized compensation expense related to unvested RSUs, which is expected to be recognized over a weighted average period of 1.8 years.

Earnings per share

We account for earnings per share in accordance with Accounting Standards Codification (“ASC”) Subtopic 260-10,Earnings Per Share (“ASC 260-10”). ASC 260-10 requires companies to present two calculations of earnings per share: basic and diluted. Basic earnings per common share for the three months ended March 31, 2014 equals net income divided by the weighted average shares outstanding during the period. Weighted average shares outstanding are equal to the weighted average of all shares outstanding for the period, excluding RSUs. Diluted earnings per common share for the three months ended March 31, 2014 are computed in the same manner as basic earnings per common share after assuming the issuance of common shares for all potentially dilutive common share equivalents, which includes RSUs.

The following table presents the basic and diluted earnings per common share computations:

	Three Months Ended March 31,
(in thousands, except per share amounts)	2014			2013
Net income from continuing operations	$	3,993		$	3,032
Net loss from discontinued operations	$	(20	)	$	(93	)
Basic net income per common share:
Shares:
Weighted average common shares outstanding		37,392			36,888
Basic net income per common share:
Continuing operations	$	0.11		$	0.08
Discontinued operations	$	0.00		$	0.00
Diluted net income per common share:
Shares:
Weighted average common shares outstanding		37,392			36,888
Diluted net income per common share:
Continuing operations	$	0.11		$	0.08
Discontinued operations	$	0.00		$	0.00

9. Segment information

In accordance with ASC 280,Segment Reporting(“ASC 280”), we have two reportable geographic segments: Turkey and Bulgaria. Summarized financial information from continuing operations concerning our geographic segments is shown in the following table:

	Corporate			Turkey		Bulgaria			Total
	(in thousands)
For the three months ended March 31, 2014
Total revenues	$	—		$	33,639	$	7		$	33,646
Income (loss) from continuing operations before income taxes		(3,820	)		7,500		2,363			6,043
Capital expenditures	$	169		$	21,781	$	1,041		$	22,991
For the three months ended March 31, 2013
Total revenues	$	—		$	33,976	$	68		$	34,044
Income (loss) from continuing operations before income taxes		(2,980	)		8,372		(100	)		5,292
Capital expenditures	$	—		$	18,699	$	—		$	18,699
Segment assets
March 31, 2014	$	14,427		$	323,302	$	7,195		$	344,924	(1)
December 31, 2013	$	14,070		$	321,749	$	10,231		$	346,050	(1)
Goodwill
March 31, 2014	$	—		$	7,344	$	—		$	7,344
December 31, 2013	$	—		$	7,535	$	—		$	7,535

(1) Excludes assets held for sale from our discontinued Moroccan operations of $29,000 and $0.5 million at March 31, 2014 and December 31, 2013, respectively.

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10. Financial instruments

Interest rate risk

We are exposed to interest rate risk as a result of our variable rate short-term cash holdings and borrowings under the Senior Credit Facility.

Foreign currency risk

We have underlying foreign currency exchange rate exposure. Our currency exposures relate to transactions denominated in the Bulgarian Lev, European Union Euro, and TRY. We are also subject to foreign currency exposures resulting from translating the functional currency of our subsidiary financial statements into the U.S. Dollar reporting currency. We have not used foreign currency forward contracts to manage exchange rate fluctuations. At March 31, 2014, we had 22.1 million TRY (approximately $10.1 million) in cash and cash equivalents, which exposes us to exchange rate risk based on fluctuations in the value of the TRY.

Commodity price risk

We are exposed to fluctuations in commodity prices for oil and natural gas. Commodity prices are affected by many factors, including but not limited to, supply and demand. At March 31, 2014 and December 31, 2013, we were a party to commodity derivative contracts. See Note 5 Commodity derivative contracts.

Concentration of credit risk

The majority of our receivables are within the oil and natural gas industry, primarily from our industry partners and from government agencies. Included in receivables are amounts due from Turkiye Petrolleri Anonim Ortakligi (“TPAO”), the national oil company of Turkey, Zorlu Dogal Gaz Ithalat Ihracat ve Toptan Ticaret A.S. (“Zorlu”), a privately owned natural gas distributor in Turkey, and TUPRAS, which purchase the majority of our oil and natural gas production. The receivables are not collateralized. To date, we have experienced minimal bad debts and have no allowance for doubtful accounts. The majority of our cash and cash equivalents are held by three financial institutions in the United States and Turkey.

Fair value measurements

Cash and cash equivalents, receivables, accounts payable, accrued liabilities, and the TBNG credit facility were each estimated to have a fair value approximating their carrying amount at March 31, 2014 and December 31, 2013 due to the short maturity of those instruments. Indebtedness under the Amended and Restated Credit Facility was estimated to have a fair value approximating the carrying amount at March 31, 2014 and December 31, 2013 since the interest rate is generally market sensitive.

The following table summarizes the valuation of our financial assets and liabilities as of March 31, 2014:

	Fair Value Measurement Classification
	Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total
	(in thousands)
Liabilities:
Derivative financial instruments (commodity)	$	—	$	(6,253	)	$	—	$	(6,253	)
Total	$	—	$	(6,253	)	$	—	$	(6,253	)

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The following table summarizes the valuation of our financial assets and liabilities as of December 31, 2013:

	Fair Value Measurement Classification
	Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total
	(in thousands)
Liabilities:
Derivative financial instruments (commodity)	$	—	$	(7,967	)	$	—	$	(7,967	)
Total	$	—	$	(7,967	)	$	—	$	(7,967	)

11. Related party transactions

The following table summarizes related party accounts receivable and accounts payable as of the dates indicated:

	March 31, 2014		December 31, 2013
	(in thousands)
Related party accounts receivable:
Viking International master services agreement	$	418	$	939
Riata Management Service Agreement		54		65
Total related party accounts receivable	$	472	$	1,004
Related party accounts payable:
Viking International master services agreement	$	16,438	$	15,956
Viking Geophysical master services agreement		2,051		6,800
Riata Management Service Agreement		382		334
Total related party accounts payable	$	18,871	$	23,090

On June 13, 2012, we entered into separate master services agreements with each of Viking International Limited (“Viking International”), Viking Petrol Sahasi Hizmetleri A.S. (“VOS”) and Viking Geophysical Services, Ltd. (“Viking Geophysical”) in connection with the sale of our oilfield services business. Pursuant to the master services agreements with Viking International and VOS, we are entitled to receive certain oilfield services and materials, including, but not limited to, drilling rigs and fracture stimulation equipment that are needed for our operations in Turkey and Bulgaria. Pursuant to the master services agreement with Viking Geophysical, we are also entitled to receive geophysical services and materials that are needed for our operations in those countries. Each master services agreement is for a five-year term.

On June 13, 2012, we entered into a transition services agreement with Viking Services Management, Ltd. (“Viking Management”) in connection with the sale of our oilfield services business. Pursuant to the transition services agreement, we agreed to provide certain administrative services, including, but not limited to, continued use of certain of our employees and independent contractors, a guarantee of a lease for flats in Turkey, Turkish tax or legal advice and services, office space in Istanbul, Turkey, information technology support and certain software or licenses to Viking Management. In addition, Viking Management agreed to cause its subsidiaries to provide us with the continued use of certain office space in Tekirdag, Turkey. In the third quarter of 2012, we entered into an addendum to the transition services agreement whereby Viking Management agreed to cause its subsidiaries to provide us with the continued use of certain equipment yards in the Thrace Basin and in southwestern Turkey. The transition services agreement has a two-year term. Viking Management agreed to use commercially reasonable efforts to eliminate its need for such services as soon as practicable following the entry into the agreement.

On March 26, 2014, our wholly owned subsidiaries, TEMI and TBNG, entered into an equipment yard services agreement effective as of April 1, 2014 with Viking International for services related to the use of oilfield equipment yards located in Diyarbakir, Tekirdag and Muratli, Turkey. The initial term of the agreement is for twelve months, and the term of the agreement renews automatically for additional twelve-month periods unless earlier terminated. During the initial term, TEMI will pay monthly service fees of $17,250 to Viking International for services related to the use of the Diyarbakir equipment yard, and TBNG will pay monthly service fees of $17,250 to Viking International for services related to the use of the Tekirdag and Muratli equipment yards.

For the three months ended March 31, 2014 and 2013, we incurred expenses of $19.0 million and $20.2 million, respectively, related to our various related party agreements.

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12. Discontinued operations

Discontinued operations in Morocco

On June 27, 2011, we decided to discontinue our operations in Morocco. We have transferred our oilfield services equipment from Morocco to Turkey and have substantially completed the process of winding down our operations in Morocco. We have presented the Moroccan segment operating results as discontinued operations for all periods presented.

The assets and liabilities held for sale are summarized as follows:

	March 31, 2014		December 31, 2013
	(in thousands)
Cash	$	16	$	23
Other assets		13		513
Total assets held for sale	$	29	$	536
Accrued expenses and other liabilities	$	7,455	$	7,559
Total liabilities held for sale	$	7,455	$	7,559

Our operating results from discontinued operations for the three months ended March 31, 2014 and 2013 are summarized as follows:

	2014			2013
	(in thousands)
Total revenues	$	—		$	—
Total costs and expenses		(20	)		(86	)
Total other expense		—			(7	)
Loss from discontinued operations before income taxes		(20	)		(93	)
Income tax provision		—			—
Loss from discontinued operations, net of taxes	$	(20	)	$	(93	)

13. Subsequent events

Senior Credit Facility. On May 6, 2014, the Borrowers entered into the Senior Credit Facility with BNP Paribas and IFC. Each of the Borrowers is our wholly owned subsidiary. The Senior Credit Facility is guaranteed by TransAtlantic Petroleum Ltd. and each of TransAtlantic Petroleum (USA) Corp. and TransAtlantic Worldwide (each, a “Guarantor”).

The amount drawn under the Senior Credit Facility may not exceed the lesser of (i) $150.0 million, (ii) the borrowing base amount at such time, (iii) the aggregate commitments of all lenders at such time, and (iv) any amount borrowed from an individual lender to the extent it exceeds the aggregate amount of such lender’s individual commitment. The lenders have initial aggregate commitments of $80.0 million, with individual commitments of $40.0 million each. The Company has the ability to increase the commitments up to $150 million by March 31, 2016. On the first day of each fiscal quarter commencing April 1, 2016, the lenders’ commitments are subject to reduction in an amount equal to 7.69% of the aggregate commitments in effect on April 1, 2016.

The borrowing base amount is re-determined semi-annually on April 1st and October 1st of each year, beginning April 1, 2015. The initial borrowing base is $78.0 million. The borrowing base amount equals, for any calculation date, the lowest of:

• the debt value which results in the field life coverage ratio for such calculation date being 1.50 to 1.00; and

• the debt value which results in the loan life coverage ratio for such calculation date being 1.30 to 1.00.

The Senior Credit Facility matures on the earlier of (i) March 31, 2019, or (ii) the last date of the borrowing base calculation period that immediately precedes the date that the semi-annual banking case of BNP Paribas and the Borrowers determines that the aggregate amount of hydrocarbons to be produced from the borrowing base assets in Turkey are less than 25% of the amount of hydrocarbons to be produced from the borrowing base assets shown in the initial banking case prepared by BNP Paribas and the Borrowers. The Senior Credit Facility bears various letter of credit sub-limits, including among other things, sub-limits of up to (i) $10.0 million, (ii) the aggregate available unused and uncancelled portion of the lenders’ commitments or (iii) any amount borrowed from an individual lender to the extent it exceeds the aggregate amount of such lender’s individual commitment.

Loans under the Senior Credit Facility accrue interest at a rate of three-month LIBOR plus 5.00% per annum. The Borrowers are also required to pay (i) a commitment fee payable quarterly in arrears at a per annum rate equal to (a) 2.00% per annum of the unused and uncancelled portion of the aggregate commitments that is less than or equal to the maximum available amount under the Senior Credit Facility, and (b) 1.00% per annum of the unused and uncancelled portion of the aggregate commitments that exceed the maximum available amount under the Senior Credit Facility and is not available to be borrowed, (ii) on the date of issuance of any letter of credit, a fronting fee in an amount equal to 0.25% of the original maximum amount to be drawn under such letter of credit and (iii) a

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per annum letter of credit fee for each letter of credit issued equal to the face amount of such letter of credit multiplied by (a) 1.0% for any letter of credit that is cash collateralized or backed by a standby letter of credit issued by a financial institution acceptable to BNP Paribas or (b) 5.00% for all other letters of credit.

The Senior Credit Facility is secured by a pledge of (i) the local collection accounts and offshore collection accounts of each of the Borrowers, (ii) the receivables payable to each of the Borrowers, (iii) the shares of each Borrower and (iv) substantially all of the present and future assets of the Borrowers.

The Borrowers are required to comply with certain financial and non-financial covenants under the Senior Credit Facility, including maintaining the following financial ratios during the four most recently completed fiscal quarters occurring on or after March 31, 2014:

• ratio of combined current assets to combined current liabilities of not less than 1.10 to 1.00;

• ratio of EBITDAX (less non-discretionary capital expenditures) to aggregate amounts payable under the Senior Credit Facility of not less than 1.50 to 1.00;

• ratio of EBITDAX (less non-discretionary capital expenditures) to interest expense of not less than 4.00 to 1.00; and

• ratio of total debt to EBITDAX of less than 2.50 to 1.00.

The Senior Credit Facility defines EBITDAX as net income (excluding extraordinary items) plus, to the extent deducted in calculating such net income, (i) interest expense (excluding interest paid-in-kind, or non-cash interest expense and interest incurred on certain subordinated intercompany debt or interest on equity recapitalized into subordinated debt), (ii) income tax expense, (iii) depreciation, depletion and amortization expense, (iv) amortization of intangibles and organization costs, (v) any extraordinary, unusual or non-recurring non-cash expenses or losses, (vi) expenses incurred in connection with oil and gas exploration activities entered into in the ordinary course of business (including related drilling, completion, geological and geophysical costs), (vii) transaction costs, expenses and fees incurred in connection with the negotiation, execution and delivery of the Senior Credit Facility and the related loan documents, minus, to the extent included in calculating net income, (a) any extraordinary, unusual or non-recurring income or gains (including, gains on the sales of assets outside of the ordinary course of business) and (b) any other non-cash income or gains.

Pursuant to the terms of the Senior Credit Facility, until amounts under the Senior Credit Facility are repaid, each of the Borrowers shall not, and shall cause each of its subsidiaries not to, in each case subject to certain exceptions (i) incur indebtedness or create any liens, (ii) enter into any agreements that prohibit the ability of any Borrower or its subsidiaries to create any liens, (iii) enter into any merger, consolidation or amalgamation, liquidate or dissolve, (iv) dispose of any property or business, (v) pay any dividends, distributions or similar payments to shareholders, (vi) make certain types of investments, (vii) enter into any transactions with an affiliate, (viii) enter into a sale and leaseback arrangement, (ix) engage in any business or business activity, own any assets or assume any liabilities or obligations except as necessary in connection with, or reasonably related to, its business as an oil and natural gas exploration and production company or operate or carry on business in any jurisdiction outside of Turkey or its jurisdiction of formation, (x) change its organizational documents, (xi) permit its fiscal year to end on a day other than December 31st or change its method of determining fiscal quarters, or alter the accounting principles it uses, (xii) modify certain hydrocarbon licenses and agreements or material contracts, (xiii) enter into any hedge agreement for speculative purposes, (xiv) open or maintain new deposit, securities or commodity accounts, (xv) use the proceeds from any loan in the territories of any country that is not a member of the World Bank, (xvi) incur any expenditure that is not covered by the projections in the most recent corporate cashflow projection, (xvii) modify its social and environmental action plans as determined in conjunction with IFC, (xviii) enter into any transaction or engage in any activity prohibited by the United Nations Security Council, or (xix) engage in any corrupt, fraudulent, coercive, collusive or obstructive practice.

An event of default under the Senior Credit Facility includes, among other events, failure to pay principal or interest when due, breach of certain covenants and obligations, cross default to other indebtedness, bankruptcy or insolvency, failure to meet the required financial covenant ratios, failure to obtain an extension of the Selmo production lease before December 31, 2014 and the occurrence of a material adverse effect. In addition, the occurrence of a change of control is an event of default. A change of control is defined as the occurrence of any of the following: (i) our failure to own, of record and beneficially, all of the equity of the Borrowers or any Guarantor or to exercise, directly or indirectly, day-to-day management and operational control of any Borrower or Guarantor; (ii) the failure by the Borrowers to own or hold, directly or indirectly, all of the interests granted to Borrowers pursuant to certain hydrocarbon licenses designated in the Senior Credit Facility; or (iii) (a) Mr. Mitchell ceases for any reason to be the executive chairman of our board of directors at any time, (b) Mr. Mitchell and certain of his affiliates cease to own of record and beneficially at least 35% of our common shares; or (c) any person or group, excluding Mr. Mitchell and certain of his affiliates, shall become, or obtain rights to become, the beneficial owner, directly or indirectly, of more than 35% of our outstanding common shares entitled to vote for members of our board of directors on a fully-diluted basis. Provided that, if Mr. Mitchell ceases to be executive chairman of our board of directors by reason of his death or disability, such event shall not constitute an event of default unless we have not appointed a successor reasonably acceptable to the lenders within 60 days of the occurrence of such event.

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We plan to use proceeds from the Senior Credit Facility to pay off in full our Amended and Restated Credit Facility by May 15, 2014 and to fund our oil and natural gas development and exploration activities in Turkey.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

In this Quarterly Report on Form 10-Q, references to “we,” “our,” “us” or the “Company,” refer to TransAtlantic Petroleum Ltd. and its subsidiaries on a consolidated basis unless the context requires otherwise. Unless stated otherwise, all sums of money stated in this Quarterly Report on Form 10-Q are expressed in U.S. Dollars.

Executive Overview

We are an international oil and natural gas company engaged in acquisition, exploration, development and production. We have focused our operations in countries that have established yet underexplored petroleum systems, are net importers of petroleum, have an existing petroleum transportation infrastructure and provide favorable commodity pricing, royalty rates and tax rates to exploration and production companies. As of March 31, 2014, we held interests in approximately 1.9 million net acres of developed and undeveloped oil and natural gas properties in Turkey and Bulgaria. As of May 1, 2014, approximately 40% of our outstanding common shares were beneficially owned by N. Malone Mitchell 3rd, our chief executive officer and chairman of our board of directors.

Financial and Operational Performance Highlights.

Highlights of our financial and operational performance for the first quarter of 2014 include:

• We reported $4.0 million of net income from continuing operations. This includes a $1.0 million gain on our commodity derivative contracts and a $2.5 million non-cash benefit from the reversal of a contingent liability related to the Decentci-R2 well in Bulgaria.

• We derived 76.5% of our oil and natural gas revenues from the production of oil and 23.5% from the production of natural gas.

• Total oil and natural gas sales revenues increased 1% to $33.0 million for the quarter ended March 31, 2014 from $32.7 million in the same period in 2013. The increase was primarily the result of an increase in sales volumes of 43 Mboe, which was partially offset by an $8.44 per Boe decrease in the average sales price received.

• Wellhead production increased to 261 net thousand barrels (“Mbbls”) of oil and 1,060 net million cubic feet (“Mmcf”) of natural gas, as compared to 244 Mbbls of oil and 856 Mmcf of natural gas for the same period in 2013.

• For the quarter ended March 31, 2014, we incurred $26.1 million in capital expenditures, including seismic and corporate expenditures, as compared to capital expenditures of $18.7 million for the quarter ended March 31, 2013.

• As of March 31, 2014, we had $49.8 million in long-term debt and $26.7 million in short-term debt, as compared to $26.5 million in long-term debt and $43.3 million in short-term debt as of December 31, 2013.

Recent Developments

Idil Farm-Out. In February 2014, our wholly owned subsidiary, TransAtlantic Turkey, Ltd. (“TransAtlantic Turkey”), and Selsinsan Petrol Maden T.O. San ve Tic. Ltd. Sti. (“Selsinsan”) entered into a farm-out agreement with Onshore Petroleum Company AS (“Onshore”), a private oil and gas company. Pursuant to the agreement, Onshore will fund 100% of our initial exploration well, up to $3.5 million, on the Idil license in southeastern Turkey. Expenses over $3.5 million will be split equally between us and Onshore. In exchange, TransAtlantic Turkey and Selsinsan assigned Onshore a 50% interest in the Idil license.

Appointment of New Director. On February 10, 2014, we appointed Gregory K. Renwick to our board of directors. Mr. Renwick worked at Mobil for 25 years and, under his leadership, Mobil successfully acquired upstream assets in Kazakhstan, Turkmenistan and Azerbaijan. He served as president and chief executive officer of East West Petroleum Corp. from 2010 to 2013 and as the director of business development for Dana Gas PJSC in the United Arab Emirates from 2007 to 2010.

Reverse Stock Split. On March 4, 2014, our shareholders approved a 1-for-10 reverse stock split, which became effective March 6, 2014. Pursuant to the reverse stock split, all shareholders of record received one common share for each ten common shares owned (subject to minor adjustments as a result of fractional shares). The reverse stock split reduced the issued and outstanding common shares from 374,026,984 to 37,402,698. U.S. GAAP requires that the reverse stock split be applied retrospectively to all periods presented. As a result, all common share amounts and transactions described herein have been adjusted to reflect the 1-for-10 reverse stock split.

Senior Credit Facility. On May 6, 2014, DMLP, Ltd. (“DMLP”), TransAtlantic Exploration Mediterranean International Pty Ltd (“TEMI”), Talon Exploration, Ltd. (“Talon Exploration”), TransAtlantic Turkey, Amity Oil International Pty. Ltd. (“Amity”) and Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayi ve Ticaret A.Ş. (“Petrogas”)(collectively, the “Borrowers”) entered into a senior secured credit facility (the “Senior Credit Facility”) with BNP Paribas (Suisse) SA (“BNP Paribas”) and the International Finance Corporation (“IFC”). Each of the Borrowers is our wholly owned subsidiary. The Senior Credit Facility is guaranteed by

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TransAtlantic Petroleum Ltd. and each of TransAtlantic Petroleum (USA) Corp. and TransAtlantic Worldwide (each, a “Guarantor”). We expect to use the proceeds from the Senior Credit Facility to pay off in full our existing senior secured credit facility by May 15, 2014 and to fund our oil and natural gas development and exploration activities in Turkey.

First Quarter 2014 Operational Update

During the first quarter of 2014, we further developed our oil fields in southeastern Turkey and our Thrace Basin natural gas fields in northwestern Turkey. We continue to make progress on the completion of one well in Bulgaria.

Turkey-Southeast

Molla. We completed shooting approximately 90% of our 800 km² Molla 3D seismic program and expect to shoot the remaining seismic in the second quarter of 2014. The final phase of processed data is projected to be delivered in the third quarter of 2014. We spudded the Bahar-2ST well to test the Bedinan formation west of the original Bahar-2 bottom-hole location. Following the Bahar-2ST, we intend to drill the Bahar-3, a vertical well planned to yield additional confirmation of the Bahar structure.

Selmo. We spudded our sixth MSD horizontal well, the Selmo-84H, which we expect to complete in the second quarter of 2014. We completed the Selmo-92H, our fifth MSD horizontal well, which had initial production of 250 barrels of oil per day (“bbl/d”) gross. We expect to spud six additional horizontal wells in the Selmo field in 2014.

We initiated a waterflood pilot test program in the Selmo field in which two Selmo wells were shut-in for conversion to injector wells. The first conversion was successfully completed, and we have begun to inject water into the Selmo field. We believe secondary recovery will increase production from the field and we intend to conduct at least two additional waterflood pilot tests in the field in 2014. Additionally, we took six Selmo wells offline to conduct polymer injection for an expected net oil enhancement.

Arpatepe. We spudded the Arpatepe-7, a Bedinan appraisal well, which we plan to complete during the second quarter of 2014. We plan to drill one additional appraisal well and initiate a waterflood pilot test during the remainder of 2014.

Turkey-Thrace Basin, Northwest

We drilled our first horizontal well in the Mezardere siltstone, the BTD-2H and completed it with an eight-stage stimulation. Initial production was 2.0 million cubic feet of natural gas per day (“Mmcf/d”) gross and production increased to 2.3 Mmcf/d gross as additional stages of the well were completed. We drilled and completed a second horizontal well in the Mezardere siltstone, the TDR-11H, with a 10-stage stimulation, and it had initial production of 2.0 Mmcf/d gross. We have processed approximately 75% of our Osmanli 3D seismic program, and expect to process the remainder of the data in the second quarter of 2014. During the remainder of 2014, we expect to drill between eight and twelve conventional shallow wells and between four and eight additional horizontal wells in the Thrace Basin.

Bulgaria

We reached target depth of 14,500 feet on the Decentci-R2 well in January 2014 and are currently conducting ongoing testing of the well.

Planned Operations

We continue to actively explore and develop our existing oil and natural gas properties in Turkey and evaluate opportunities for further activities in Bulgaria. Our success will depend in part on discovering additional hydrocarbons in commercial quantities and then bringing these discoveries into production. For the remainder of 2014, we are focused on accomplishing the following objectives:

• Increase Reserves and Production. We increased our proved reserves by 5.4% in 2013. Based on our 2013 exit rate, we increased our average daily wellhead production rate by 24% during the second half of 2013. We plan to continue to increase our oil and natural gas reserves and production in Turkey through exploration and development on our Selmo, Molla and Thrace Basin exploration licenses and production leases, including the application of 3D seismic, horizontal drilling and fracture stimulation techniques. During the remainder of 2014, we plan to drill or participate in the drilling of between 14 and 22 new gross wells in southeastern Turkey and between 12 and 20 new gross wells in northwestern Turkey, and recomplete between 10 and 20 existing gross wells in northwestern Turkey.

• Utilize New 3D Seismic Data to Improve Well Targeting. During 2013, we spent $12.8 million shooting 3D seismic over areas of Turkey where 3D seismic data did not previously exist. We expect this new data will improve our ability to target well locations, drill wells and ultimately delineate hydrocarbon reservoirs.

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• Expand the Use of Horizontal Drilling. During 2013, we expanded our use of horizontal drilling, employing it on 13 of 35 wells drilled, with successful results in the Selmo, Molla and Thrace Basin areas. During the remainder of 2014, we anticipate extensive use of horizontal drilling techniques on our wells in southeastern and northwestern Turkey to more effectively extract hydrocarbons and increase our returns on invested capital.

• Continue to Expand Fracture Stimulation Program. In 2013, we expanded our use of hydraulic fracturing technology to complete otherwise low productive formations in Turkey. The evolution of fracturing fluids and stimulation designs has yielded positive results in both northwestern and southeastern Turkey. For the remainder 2014, we plan to continue optimizing our hydraulic fracturing techniques to improve well performance and economics.

We expect net field capital expenditures for the remainder of 2014 to range between $55.0 million and $70.0 million for the drilling and completion of between 26 and 42 gross wells, the recompletion of between 10 and 20 existing gross wells, the processing of remaining seismic data, infrastructure improvements and other capital investments. Of these expenditures, we expect to spend approximately 15% in northwestern Turkey, devoted to developing conventional and unconventional natural gas production and building infrastructure. Most of the remaining 85% of these anticipated expenditures is expected to be invested in southeastern Turkey, devoted to drilling developmental and exploratory oil wells at Selmo, Arpatepe and Molla and acquiring seismic data. We expect cash on hand, borrowings from our credit facilities and cash flow from operations will be sufficient to fund the remainder of our 2014 net field capital expenditures. If not, we will either curtail our discretionary capital expenditures or seek other funding sources. Our projected 2014 capital expenditure budget is subject to change. We currently plan to execute the following drilling and exploration activities during the second, third and fourth quarters of 2014:

Turkey. We plan to drill between 26 and 42 gross wells, between 17 and 25 of which are expected to be drilled horizontally and approximately 75% of which will be fracture stimulated. We also plan to continue our waterflood pilot test program.

Bulgaria. We plan to further evaluate exploration activities on our Koynare Production Concession following the results from our testing of the Deventci-R2 well.

Discontinued Operations in Morocco

In June 2011, we decided to discontinue our Moroccan operations. We have substantially completed the process of winding down our operations in Morocco. We have presented the Moroccan segment operating results as discontinued operations for the three months ended March 31, 2014 and March 31, 2013.

Significant Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”). The preparation of these consolidated financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenue and expenses, and related disclosures. Our significant accounting policies are described in “Note 3. Significant accounting policies” to our audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2013 and are of particular importance to the portrayal of our financial position and results of operations and require the application of significant judgment by management. These estimates are based on historical experience, information received from third parties, and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. There have been no changes to the significant accounting policies disclosed in our Annual Report on Form 10-K for the year ended December 31, 2013.

Recent Accounting Pronouncements

In April 2014, the Financial Accounting Standard Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-08,Reporting Discontinued Operations and Disclosures of Components of an Entity(“ASU 2014-08”). ASU 2014-08 revises the definition of discontinued operations by limiting discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have (or will have) a major effect on an entity’s operations and financial results, removing the lack of continuing involvement criteria and requiring discontinued operations reporting for the disposal of an equity method investment that meets the definition of discontinued operations. The update also requires expanded disclosures for discontinued operations, including disclosure of pretax profit or loss of an individually significant component of an entity that does not qualify for discontinued operations reporting. The update is effective prospectively to all periods beginning after December 15, 2014. We do not expect the adoption of ASU 2014-08 to have a material impact on our consolidated financial statements or results of operations.

We have reviewed other recently issued, but not yet adopted, accounting standards in order to determine their effects, if any, on our results of operations, financial position and cash flows. Based on that review, we believe that none of these pronouncements will have a significant effect on our current or future earnings or operations.

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Results of Operations—Three Months Ended March 31, 2014 Compared to Three Months Ended March 31, 2013

Our results of operations for the three months ended March 31, 2014 and 2013 were as follows:

	Three Months Ended March 31,						Change
	2014			2013			2014-2013
	(in thousands of U.S. Dollars, except per unit amounts and production volumes)
Wellhead production:
Oil (Mbbl)		261			244			17
Natural gas (Mmcf)		1,060			856			204
Total production (Mboe)		438			387			51
Average daily wellhead production (Boepd)		4,866			4,300			566
Sales volumes:
Oil (Mbbl)		260			239			21
Natural gas (Mmcf)		934			801			133
Total sales volumes (Mboe)		416			373			43
Average daily sales volumes (Boepd)		4,622			4,144			478
Average sales prices:
Oil (per Bbl)	$	97.05		$	103.00		$	(5.95	)
Natural gas (per Mcf)	$	8.30		$	10.12		$	(1.82	)
Oil equivalent (per Boe)	$	79.29		$	87.73		$	(8.44	)
Revenues:
Oil and natural gas sales		32,984			32,725			259
Sale of purchased natural gas		545			806			(261	)
Other		117			513			(396	)
Total revenues		33,646			34,044			(398	)
Costs and expenses:
Production		4,131			5,527			(1,396	)
Exploration, abandonment and impairment		4,141			3,864			277
Cost of purchased natural gas		485			712			(227	)
Seismic and other exploration		3,294			243			3,051
Revaluation of contingent consideration		(2,500	)		—			(2,500	)
General and administrative		6,552			7,523			(971	)
Depletion		9,559			8,386			1,173
Depreciation and amortization		531			590			(59	)
Interest and other expense		1,203			890			313
Foreign exchange loss		1,344			487			857
Gain (loss) on commodity derivative contracts:
Cash settlements on commodity derivative contracts		(752	)		(1,252	)		500
Change in fair value on commodity derivative contracts		1,714			476			1,238
Total loss on commodity derivative contracts		962			(776	)		1,738
Oil and natural gas costs per Boe(1):
Production	$	8.70		$	12.97		$	(4.27	)
Depletion	$	20.12		$	19.69		$	0.43

(1) We have recalculated the oil and natural gas costs per Boe for the three months ended March 31, 2013 based on working interest volumes before royalty deductions to conform to current-year presentation.

Oil and Natural Gas Sales. Total oil and natural gas sales revenues increased $0.3 million to $33.0 million for the three months ended March 31, 2014, from $32.7 million realized in the same period in 2013. Of the increase, $3.8 million was due to an increase in sales volumes of 43 Mboe. This was partially offset by a decrease of $3.5 million, primarily due to lower average realized prices per Boe. Our average price received decreased $8.44 per Boe to $79.29 per Boe for the three months ended March 31, 2014, from $87.73 per Boe for the same period in 2013.

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Production.Production expenses for the three months ended March 31, 2014 decreased to $4.1 million or $8.70 per Boe from $5.5 million or $12.97 per Boe for the same period in 2013. The decrease was primarily due to less workover activity of $0.8 million during the three months ended March 31, 2014 and a reduction in severance expense to field employees of $0.6 million.

Exploration, Abandonment and Impairment.Exploration, abandonment and impairment costs for the three months ended March 31, 2014 increased $0.2 million to $4.1 million, from $3.9 million for the same period in 2013. During the three months ended March 31, 2014, one well was impaired for $3.5 million, as compared to the three months ended March 31, 2013, when there were three wells written off for a total of $3.4 million.

Seismic and Other Exploration.Seismic and other exploration costs increased to $3.3 million for the three months ended March 31, 2014, compared to $0.2 million for the same period in 2013. The increase was primarily due to seismic acquisition activities conducted on our West Molla license during the three months ended March 31, 2014.

General and Administrative. General and administrative expense was $6.6 million for the three months ended March 31, 2014, compared to $7.5 million for the same period in 2013. The decrease was primarily due to $0.5 million decrease in employee-related costs resulting from a reduction in head count and a $0.3 million decrease in office expenses and rent.

Depletion.Depletion increased to $9.6 million or $20.12 per Boe for the three months ended March 31, 2014, compared to $8.4 million or $19.69 per Boe for the same period of 2013. The increase was primarily due to additions to proved properties during the three months ended March 31, 2014.

Depreciation and Amortization.Depreciation and amortization decreased to $0.5 million for the three months ended March 31, 2014, compared to $0.6 million for the same period of 2013.

Interest and Other Expense. Interest and other expense increased to $1.2 million for the three months ended March 31, 2014, compared to $0.9 million for the same period in 2013. The increase was due to an increase in our average level of debt outstanding during the three months ended March 31, 2014 compared to the same period in 2013. At March 31, 2014, we had $76.5 million of total debt outstanding, as compared to $39.8 million at March 31, 2013.

Foreign Exchange Loss. We recorded a foreign exchange loss of $1.3 million during the three months ended March 31, 2014, compared to a loss of $0.5 million in the same period in 2013. The change in foreign exchange is primarily unrealized (non-cash) in nature and results from the re-measuring of specific transactions and monetary accounts in a currency other than the functional currency. For example, a U.S. Dollar transaction which occurs in Turkey is re-measured at the period-end to the New Turkish Lira (“TRY”) amount if it has not been settled previously. The increase in foreign exchange loss in the three months ended March 31, 2014 was due to a 2.6% decrease in the value of the TRY compared to the U.S. Dollar, compared to the change in the value of the TRY for the three months ended March 31, 2013.

Gain (Loss) on Commodity Derivative Contracts. During the three months ended March 31, 2014, we recorded a net gain on commodity derivative contracts of approximately $1.0 million, compared to a net loss of $0.8 million for the same period in 2013. During the three months ended March 31, 2014, we recorded a $1.7 million gain to mark our commodity derivative contracts to their fair value and a $0.7 million loss on settled contracts. During the same period in 2013, we recorded a $0.5 million gain to mark our derivative contracts to their fair value and a $1.3 million loss on settled contracts. We are required under our Amended and Restated Credit Facility to hedge between 30% and 75% of our anticipated oil production volumes in our oil fields in Turkey.

Discontinued Operations. All revenues and expenses associated with our Moroccan operations for the three months ended March 31, 2014 and 2013 have been included in discontinued operations.

The results of these discontinued operations were as follows:

	Three Months Ended March 31,
	2014			2013
	(in thousands)
Costs and expenses:
Production	$	—		$	69
General and administrative		20			17
Total costs and expenses		20			86
Operating loss		(20	)		(86	)
Other expense:
Interest and other expense		—			(7	)
Total other expense		—			(7	)
Net loss from discontinued operations, net of taxes	$	(20	)	$	(93	)

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Capital Expenditures

For the quarter ended March 31, 2014, we incurred $26.1 million in capital expenditures, including seismic and corporate expenditures, compared to $18.7 million for the quarter ended March 31, 2013. The increase in capital expenditures was primarily due to increased drilling and completion activities in the Selmo field and the seismic acquisition activities conducted in southeastern Turkey.

We expect net field capital expenditures for the remainder of 2014 to range between $55.0 million and $70.0 million for the drilling and completion of between 26 and 42 gross wells, the recompletion of between 10 and 20 existing gross wells, the processing of remaining seismic data, infrastructure improvements and other capital investments. Of these expenditures, we expect to spend approximately 15% in northwestern Turkey, devoted to developing conventional and unconventional natural gas production and building infrastructure. Most of the remaining 85% of these anticipated expenditures is expected to be invested in southeastern Turkey, devoted to drilling developmental and exploratory oil wells at Selmo, Arpatepe and Molla and acquiring seismic data. We expect cash on hand, borrowings from our credit facilities and cash flow from operations will be sufficient to fund the remainder of our 2014 net field capital expenditures. If not, we will either curtail our discretionary capital expenditures or seek other funding sources. Our projected 2014 capital expenditure budget is subject to change.

Liquidity and Capital Resources

Our primary sources of liquidity for the first quarter of 2014 were our cash and cash equivalents and borrowings under our Amended and Restated Credit Facility and TBNG credit facility. At March 31, 2014, we had cash and cash equivalents of $16.7 million, $49.8 million in long-term debt, $26.7 million in short-term debt and a working capital deficit of $15.6 million (excluding assets and liabilities held for sale, deferred income taxes and derivative liabilities), compared to cash and cash equivalents of $12.9 million, $26.5 million in long-term debt, $43.3 million in short-term debt and a working capital deficit of $39.4 million at December 31, 2013 (excluding assets and liabilities held for sale, deferred income taxes and derivative liabilities). Cash provided by operating activities from continuing operations during the first quarter of 2014 was $28.2 million, compared to cash provided by operating activities from continuing operations of $19.6 million in the first quarter of 2013.

Cash used in investing activities from continuing operations during the first quarter of 2014 increased to $31.2 million, compared to cash used in investing activities from continuing operations of $21.7 million in the first quarter of 2013, due primarily to increased drilling and completions activities conducted on our Selmo oil field. Additionally, cash provided by financing activities from continuing operations decreased to $6.6 million in the first quarter of 2014, compared to cash provided by financing activities from continuing operations of $7.0 million in the first quarter of 2013, due primarily to a reduction in borrowings.

As of March 31, 2014, the outstanding principal amount of our debt was $76.6 million. In addition to cash, cash equivalents and cash flow from operations, at May 6, 2014, we had the Amended and Restated Credit Facility, the Senior Credit Facility and the TBNG Credit Facility, all of which are described below.

Amended and Restated Credit Facility. The Borrowers are borrowers under the Amended and Restated Credit Facility. Each of the Borrowers is our wholly owned subsidiary. The Amended and Restated Credit Facility is guaranteed by TransAtlantic Petroleum Ltd. and each of TransAtlantic Petroleum (USA) Corp. and TransAtlantic Worldwide.

The amount drawn under the Amended and Restated Credit Facility may not exceed the lesser of (i) $250.0 million, (ii) the borrowing base amount at such time, (iii) the aggregate commitments of all lenders at such time, and (iv) any amount borrowed from an individual lender to the extent it exceeds the aggregate amount of such lender’s individual commitment. At March 31, 2014, the lenders had aggregate commitments of $60.0 million, with individual commitments of $30.0 million each.

Availability under the Amended and Restated Credit Facility is subject to a borrowing base. The borrowing base is re-determined quarterly on January 1st, April 1st, July 1st and October 1st of each year. Following our borrowing base redetermination on January 1, 2014, the borrowing base is currently $43.1 million. At March 31, 2014, we had borrowed $49.8 million under the Amended and Restated Credit Facility. The lenders have granted the Borrowers a waiver to extend until May 15, 2014 a mandatory prepayment due as a result of our borrowings exceeding the borrowing base.

At March 31, 2013, we were not in compliance with Section 8.17(a) of our Amended and Restated Credit Facility, which requires the Borrowers to maintain a current ratio of not less than 1.10:1.0. The lenders have granted the Borrowers a waiver on the current ratio requirement through March 31, 2015.

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Pursuant to the Amended and Restated Credit Facility, TEMI entered into costless derivative contracts and three-way collar contracts with Standard Bank and BNP Paribas, which hedge the price of oil during 2014 and 2015.

Senior Credit Facility. On May 6, 2014, the Borrowers entered into the Senior Credit Facility with BNP Paribas and IFC. The Senior Credit Facility is guaranteed by TransAtlantic Petroleum Ltd. and each of TransAtlantic Petroleum (USA) Corp. and TransAtlantic Worldwide.

The amount drawn under the Senior Credit Facility may not exceed the lesser of (i) $150.0 million, (ii) the borrowing base amount at such time, (iii) the aggregate commitments of all lenders at such time, and (iv) any amount borrowed from an individual lender to the extent it exceeds the aggregate amount of such lender’s individual commitment. The lenders have initial aggregate commitments of $80.0 million, with individual commitments of $40.0 million each. The Company has the ability to increase the commitments up to $150 million by March 31, 2016. On the first day of each fiscal quarter commencing April 1, 2016, the lenders’ commitments are subject to reduction in an amount equal to 7.69% of the aggregate commitments in effect on April 1, 2016.

The borrowing base amount is re-determined semi-annually on April 1st and October 1st of each year, beginning April 1, 2015. The initial borrowing base is $78.0 million. The borrowing base amount equals, for any calculation date, the lowest of:

• the debt value which results in the field life coverage ratio for such calculation date being 1.50 to 1.00; and

• the debt value which results in the loan life coverage ratio for such calculation date being 1.30 to 1.00.

The Senior Credit Facility matures on the earlier of (i) March 31, 2019, or (ii) the last date of the borrowing base calculation period that immediately precedes the date that the semi-annual banking case of BNP Paribas and the Borrowers determines that the aggregate amount of hydrocarbons to be produced from the borrowing base assets in Turkey are less than 25% of the amount of hydrocarbons to be produced from the borrowing base assets shown in the initial banking case prepared by BNP Paribas and the Borrowers. The Senior Credit Facility bears various letter of credit sub-limits, including among other things, sub-limits of up to (i) $10.0 million, (ii) the aggregate available unused and uncancelled portion of the lenders’ commitments or (iii) any amount borrowed from an individual lender to the extent it exceeds the aggregate amount of such lender’s individual commitment.

Loans under the Senior Credit Facility accrue interest at a rate of three-month LIBOR plus 5.00% per annum. The Borrowers are also required to pay (i) a commitment fee payable quarterly in arrears at a per annum rate equal to (a) 2.00% per annum of the unused and uncancelled portion of the aggregate commitments that is less than or equal to the maximum available amount under the Senior Credit Facility, and (b) 1.00% per annum of the unused and uncancelled portion of the aggregate commitments that exceed the maximum available amount under the Senior Credit Facility and is not available to be borrowed, (ii) on the date of issuance of any letter of credit, a fronting fee in an amount equal to 0.25% of the original maximum amount to be drawn under such letter of credit and (iii) a per annum letter of credit fee for each letter of credit issued equal to the face amount of such letter of credit multiplied by (a) 1.0% for any letter of credit that is cash collateralized or backed by a standby letter of credit issued by a financial institution acceptable to BNP Paribas or (b) 5.00% for all other letters of credit.

The Senior Credit Facility is secured by a pledge of (i) the local collection accounts and offshore collection accounts of each of the Borrowers, (ii) the receivables payable to each of the Borrowers, (iii) the shares of each Borrower and (iv) substantially all of the present and future assets of the Borrowers.

The Borrowers are required to comply with certain financial and non-financial covenants under the Senior Credit Facility, including maintaining the following financial ratios during the four most recently completed fiscal quarters occurring on or after March 31, 2014:

• ratio of combined current assets to combined current liabilities of not less than 1.10 to 1.00;

• ratio of EBITDAX (less non-discretionary capital expenditures) to aggregate amounts payable under the Senior Credit Facility of not less than 1.50 to 1.00;

• ratio of EBITDAX (less non-discretionary capital expenditures) to interest expense of not less than 4.00 to 1.00; and

• ratio of total debt to EBITDAX of less than 2.50 to 1.00.

        The Senior Credit Facility defines EBITDAX as net income (excluding extraordinary items) plus, to the extent deducted in calculating such net income, (i) interest expense (excluding interest paid-in-kind, or non-cash interest expense and interest incurred on certain subordinated intercompany debt or interest on equity recapitalized into subordinated debt), (ii) income tax expense, (iii) depreciation, depletion and amortization expense, (iv) amortization of intangibles and organization costs, (v) any extraordinary, unusual or non-recurring non-cash expenses or losses, (vi) expenses incurred in connection with oil and gas exploration activities entered into in the ordinary course of business (including related drilling, completion, geological and geophysical costs), (vii) transaction costs, expenses and fees incurred in connection with the negotiation, execution and delivery of the Senior Credit Facility and the related loan documents, minus, to the extent included in calculating net income, (a) any extraordinary, unusual or non-recurring income or gains (including, gains on the sales of assets outside of the ordinary course of business) and (b) any other non-cash income or gains.

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Pursuant to the terms of the Senior Credit Facility, until amounts under the Senior Credit Facility are repaid, each of the Borrowers shall not, and shall cause each of its subsidiaries not to, in each case subject to certain exceptions (i) incur indebtedness or create any liens, (ii) enter into any agreements that prohibit the ability of any Borrower or its subsidiaries to create any liens, (iii) enter into any merger, consolidation or amalgamation, liquidate or dissolve, (iv) dispose of any property or business, (v) pay any dividends, distributions or similar payments to shareholders, (vi) make certain types of investments, (vii) enter into any transactions with an affiliate, (viii) enter into a sale and leaseback arrangement, (ix) engage in any business or business activity, own any assets or assume any liabilities or obligations except as necessary in connection with, or reasonably related to, its business as an oil and natural gas exploration and production company or operate or carry on business in any jurisdiction outside of Turkey or its jurisdiction of formation, (x) change its organizational documents, (xi) permit its fiscal year to end on a day other than December 31st or change its method of determining fiscal quarters, or alter the accounting principles it uses, (xii) modify certain hydrocarbon licenses and agreements or material contracts, (xiii) enter into any hedge agreement for speculative purposes, (xiv) open or maintain new deposit, securities or commodity accounts, (xv) use the proceeds from any loan in the territories of any country that is not a member of the World Bank, (xvi) incur any expenditure that is not covered by the projections in the most recent corporate cashflow projection, (xvii) modify its social and environmental action plans as determined in conjunction with IFC, (xviii) enter into any transaction or engage in any activity prohibited by the United Nations Security Council, or (xix) engage in any corrupt, fraudulent, coercive, collusive or obstructive practice.

An event of default under the Senior Credit Facility includes, among other events, failure to pay principal or interest when due, breach of certain covenants and obligations, cross default to other indebtedness, bankruptcy or insolvency, failure to meet the required financial covenant ratios, failure to obtain an extension of the Selmo production lease before December 31, 2014 and the occurrence of a material adverse effect. In addition, the occurrence of a change of control is an event of default. A change of control is defined as the occurrence of any of the following: (i) our failure to own, of record and beneficially, all of the equity of the Borrowers or any Guarantor or to exercise, directly or indirectly, day-to-day management and operational control of any Borrower or Guarantor; (ii) the failure by the Borrowers to own or hold, directly or indirectly, all of the interests granted to Borrowers pursuant to certain hydrocarbon licenses designated in the Senior Credit Facility; or (iii) (a) Mr. Mitchell ceases for any reason to be the executive chairman of our board of directors at any time, (b) Mr. Mitchell and certain of his affiliates cease to own of record and beneficially at least 35% of our common shares; or (c) any person or group, excluding Mr. Mitchell and certain of his affiliates, shall become, or obtain rights to become, the beneficial owner, directly or indirectly, of more than 35% of our outstanding common shares entitled to vote for members of our board of directors on a fully-diluted basis. Provided that, if Mr. Mitchell ceases to be executive chairman of our board of directors by reason of his death or disability, such event shall not constitute an event of default unless we have not appointed a successor reasonably acceptable to the lenders within 60 days of the occurrence of such event.

We plan to use proceeds from the Senior Credit Facility to pay off in full our Amended and Restated Credit Facility by May 15, 2014 and to fund our oil and natural gas development and exploration activities in Turkey.

TBNG Credit Facility. On June 18, 2013, TBNG entered into a 78.8 million TRY (approximately $36.0 million at March 31, 2014) unsecured line of credit with a Turkish bank, of which 60 million TRY is available in cash for TBNG and 18.8 million TRY is available in the form of non-cash bank guarantees and letters of credit for TBNG and several other of our wholly owned subsidiaries operating in Turkey. The interest rate will be established at the time of each borrowing. We have made three borrowings under this credit facility, each of which has a one-year term at a fixed interest rate of 4.6% per annum. At maturity, we expect to renew the borrowings for one additional year at then current market interest rates. As of March 31, 2014, we had borrowed $26.7 million under this credit facility.

Contingencies Relating to Exploration Permits

We are involved in litigation with persons who claim ownership of a portion of the surface at the Selmo oil field in Turkey. These cases are being vigorously defended by TEMI and Turkish governmental authorities. We do not have enough information to estimate the potential additional operating costs we would incur in the event the purported surface owners’ claims are ultimately successful. Any adjustment arising out of the claims will be recorded when it becomes probable and measurable.

In the second quarter of 2012, we were notified that the Moroccan government may seek to recover approximately $5.5 million in contractual obligations under our Tselfat exploration permit work program. In February 2013, the Moroccan government drew down our $1.0 million bank guarantee that was put in place to ensure our performance of the Tselfat exploration permit work program. Although we believe that the bank guarantee satisfies our contractual obligations, we recorded $5.0 million in accrued liabilities relating to our Tselfat exploration permit during 2012 for this contingency.

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In the second quarter of 2012, we were notified that the Bulgarian government may seek to recover approximately $2.0 million in contractual obligations under our Aglen exploration permit work program. Due to the Bulgarian government’s January 2012 ban on fracture stimulation and related activities, a force majeure event under the terms of the exploration permit was recognized by the government. Although we invoked force majeure, we recorded $2.0 million in general and administrative expense relating to our Aglen exploration permit during 2012 for this contractual obligation.

Pursuant to the purchase agreement (the “Purchase Agreement”) with Direct Petroleum Exploration, Inc. (“Direct”), $10.0 million worth of our common shares would be due if we have not completed certain obligations relating to the drilling of the Deventci-R2 well and the coring of the Etropole shale formation. A $10.0 million provision for this contingency was accrued at December 31, 2011. In July 2013, we entered into a second amendment (the “Amendment”) to the Purchase Agreement with Direct. The Amendment sets forth a new obligation to drill and test the Deventci-R2 well by May 1, 2014. We completed the drilling and testing requirements in April 2014, which resulted in the reversal of the $2.5 million contingent liability recorded in 2011, which we recognized in our consolidated statements of comprehensive income under the caption “Revaluation of contingent consideration” during the three months ended March 31, 2014.

Contractual Obligations

There were no material changes to our contractual obligations set forth in our Annual Report on Form 10-K for the year ended December 31, 2013.

Off-Balance Sheet Arrangements

We did not have any off-balance sheet arrangements at March 31, 2014.

Forward-Looking Statements

Certain statements contained in this Quarterly Report on Form 10-Q are “forward-looking statements” and are prospective. Forward-looking statements are typically identified by words such as “anticipate,” “believe,” “expect,” “plan,” “intend,” “may,” “project,” “forecast,” “estimate,” “continue,” “would,” “could” or similar words suggesting future outcomes or statements regarding an outlook. Such forward-looking statements are subject to risks, uncertainties and other factors which could cause actual results to differ materially from future results expressed or implied by such forward-looking statements. The following factors, among others, could cause actual results to differ from those set forth in the forward-looking statements: market prices for natural gas, natural gas liquids and oil products; estimates of reserves and economic assumptions; the ability to produce and transport natural gas, natural gas liquids and oil; the results of exploration and development drilling and related activities; economic conditions in the countries and provinces in which we carry on business, especially economic slowdowns; actions by governmental authorities, receipt of required approvals, increases in taxes, legislative and regulatory initiatives relating to fracture stimulation activities, changes in environmental and other regulations, and renegotiations of contracts; political uncertainty, including actions by insurgent groups or other conflict; the negotiation and closing of material contracts; shortages of drilling rigs, equipment or oilfield services; and the other factors discussed in other documents that we file with or furnish to the Securities and Exchange Commission (“SEC”). The impact of any one factor on a particular forward-looking statement is not determinable with certainty, as such factors are interdependent upon other factors. In that regard, any statements as to future natural gas or oil production levels; capital expenditures; the allocation of capital expenditures to exploration and development activities; sources of funding for our capital program; drilling of new wells; demand for natural gas and oil products; expenditures and allowances relating to environmental matters; dates by which certain areas will be developed or will come on-stream; expected finding and development costs; future production rates; ultimate recoverability of reserves; dates by which transactions are expected to close; cash flows; uses of cash flows; collectability of receivables; availability of trade credit; expected operating costs; changes in any of the foregoing and other statements using forward-looking terminology are forward-looking statements.

Readers are cautioned not to place undue reliance on forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other things contemplated by the forward-looking statements will not occur.

Forward-looking statements in this Quarterly Report on Form 10-Q are based on management’s beliefs and opinions at the time the statements are made. The forward-looking statements contained in this Quarterly Report on Form 10-Q are expressly qualified in their entirety by this cautionary statement. The forward-looking statements included in this Quarterly Report on Form 10-Q are made as of the date of this Quarterly Report on Form 10-Q and we undertake no obligation to publicly update or revise any forward-looking statements to reflect new information, future events or otherwise, except as required by applicable securities laws.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

During the first quarter of 2014, there were no material changes in market risk exposures, or their management, that would affect the Quantitative and Qualitative Disclosures About Market Risk disclosed in our Annual Report on Form 10-K for the year ended December 31, 2013. Our oil derivatives contracts are settled based on Arab Medium crude oil pricing. The following tables set forth our outstanding derivatives contracts with respect to future crude oil production as of March 31, 2014:

Fair Value of Derivative Instruments as of March 31, 2014

Type	Period	Quantity (Bbl/day)		Weighted Average Minimum Price (per Bbl)		Weighted Average Maximum Price (per Bbl)		Estimated Fair Value of Liability
								(in thousands)
Collar	April 1, 2014—December 31, 2014		614	$	80.72	$	117.84	$	(192	)
								$	(192	)

		Collars						Additional Call
Type	Period	Quantity (Bbl/day)		Weighted Average Minimum Price (per Bbl)		Weighted Average Maximum Price (per Bbl)		Weighted Average Maximum Price (per Bbl)		Estimated Fair Value of Liability
										(in thousands)
Three-way collar contract	April 1, 2014—December 31, 2014		708	$	85.00	$	97.13	$	162.13	$	(1,988	)
Three-way collar contract	January 1, 2015—December 31, 2015		1,016	$	85.00	$	91.88	$	151.88		(4,073	)
										$	(6,061	)

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is accumulated and communicated to management, including our chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

As of March 31, 2014, management carried out an evaluation, under the supervision and with the participation of our chief executive officer and chief financial officer, of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act). Based upon the evaluation, and as a result of the material weaknesses in internal control over financial reporting described in our Annual Report on Form 10-K for the year ended December 31, 2013, our chief executive officer and chief financial officer concluded that, as of March 31, 2014, our disclosure controls and procedures were not effective at the reasonable assurance level.

There are inherent limitations to the effectiveness of any system of disclosure controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurances of achieving their control objectives.

Changes in Internal Control over Financial Reporting

There were no changes during the first quarter of 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

During the first quarter of 2014, there were no material developments to the Legal Proceedings disclosed in “Part I, Item 3. Legal Proceedings” in our Annual Report on Form 10-K for the year ended December 31, 2013.

Item 1A. Risk Factors

During the first quarter of 2014, there were no material changes to the Risk Factors disclosed in “Part I, Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2013.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

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Item 6. Exhibits

3.1	Certificate of Continuance of TransAtlantic Petroleum Ltd., dated October 1, 2009 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated October 1, 2009, filed with the SEC on October 7, 2009).
3.2	Altered Memorandum of Continuance of TransAtlantic Petroleum Ltd., dated March 4, 2014 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated March 6, 2014, filed with the SEC on March 6, 2014).
3.3	Amended Bye-Laws of TransAtlantic Petroleum Ltd., dated March 4, 2014 (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K dated March 6, 2014, filed with the SEC on March 6, 2014).
10.1	Equipment Yard Services Agreement, by and between TransAtlantic Exploration Mediterranean International Pty Ltd, Thrace Basin Natural Gas (Turkiye) Corporation and Viking International Limited, dated as of April 1, 2014 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated March 26, 2014, filed with the SEC on March 28, 2014).
10.2*	Credit Agreement, dated as of May 6, 2014, by and between Amity Oil International Pty Ltd, DMLP, Ltd., Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayi ve Ticaret A.Ş., Talon Exploration, Ltd., TransAtlantic Exploration Mediterranean International Pty. Ltd., TransAtlantic Turkey, Ltd., as borrowers, TransAtlantic Petroleum Ltd., TransAtlantic Petroleum (USA) Corp., TransAtlantic Worldwide, Ltd., as guarantors, the lenders party thereto from time to time, and BNP Paribas (Suisse) SA as coordinating mandated lead arranger, sole bookrunner, letter of credit issuer, administrative agent, collateral agent and technical agent and International Finance Corporation, as mandated lead arranger.
31.1*	Certification of the Chief Executive Officer of the Company, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of the Chief Financial Officer of the Company, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certification of the Chief Executive Officer and Chief Financial Officer of the Company, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	XBRL Instance Document.
101.SCH*	XBRL Taxonomy Extension Schema Document.
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document.

* Filed herewith.

** Furnished herewith.

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Signatures

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

By:	/s/ N. MALONE MITCHELL 3rd
	N. Malone Mitchell 3rd Chief Executive Officer
By:	/s/ WIL F. SAQUETON
	Wil F. Saqueton Chief Financial Officer
Date: May 8, 2014

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INDEX TO EXHIBITS

3.1	Certificate of Continuance of TransAtlantic Petroleum Ltd., dated October 1, 2009 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated October 1, 2009, filed with the SEC on October 7, 2009).
3.2	Altered Memorandum of Continuance of TransAtlantic Petroleum Ltd., dated March 4, 2014 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated March 6, 2014, filed with the SEC on March 6, 2014).
3.3	Amended Bye-Laws of TransAtlantic Petroleum Ltd., dated March 4, 2014 (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K dated March 6, 2014, filed with the SEC on March 6, 2014).
10.1	Equipment Yard Services Agreement, by and between TransAtlantic Exploration Mediterranean International Pty Ltd, Thrace Basin Natural Gas (Turkiye) Corporation and Viking International Limited, dated as of April 1, 2014 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated March 26, 2014, filed with the SEC on March 28, 2014).
10.2*	Credit Agreement, dated as of May 6, 2014, by and between Amity Oil International Pty Ltd, DMLP, Ltd., Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayi ve Ticaret A.Ş., Talon Exploration, Ltd., TransAtlantic Exploration Mediterranean International Pty. Ltd., TransAtlantic Turkey, Ltd., as borrowers, TransAtlantic Petroleum Ltd., TransAtlantic Petroleum (USA) Corp., TransAtlantic Worldwide, Ltd., as guarantors, the lenders party thereto from time to time, and BNP Paribas (Suisse) SA as coordinating mandated lead arranger, sole bookrunner, letter of credit issuer, administrative agent, collateral agent and technical agent and International Finance Corporation, as mandated lead arranger.
31.1*	Certification of the Chief Executive Officer of the Company, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of the Chief Financial Officer of the Company, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certification of the Chief Executive Officer and Chief Financial Officer of the Company, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	XBRL Instance Document.
101.SCH*	XBRL Taxonomy Extension Schema Document.
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document.

* Filed herewith.

** Furnished herewith.

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